Power generation system exhaust cooling

ABSTRACT

An airflow control system for a combined cycle turbomachine system in accordance with an embodiment includes: an airflow generation system for attachment to a rotatable shaft of a gas turbine system, the airflow generation system drawing in an excess flow of air through an air intake section; a mixing area for receiving an exhaust gas stream produced by the gas turbine system; an air extraction system for extracting a first portion of the excess flow of air to provide bypass air, and for diverting the bypass air into the mixing area to reduce a temperature of the exhaust gas stream; and an airflow regulation system for diverting a second portion of the excess flow of air into the compressor component and, in response to an under-frequency grid event, for increasing the second portion of the excess flow of air diverted into the compressor component.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is related to co-pending US application numbers: application Ser. No. 14/753,064, application Ser. No. 14/753,066, application Ser. No. 14/753,072, application Ser. No. 14/753,073, application Ser. No. 14/753,074, application Ser. No. 14/753,077, application Ser. No. 14/753,080, application Ser. No. 14/753,085, application Ser. No. 14/753,088, application Ser. No. 14/753,093, application Ser. No. 14/753,102, application Ser. No. 14/753,107, application Ser. No. 14/753,097, all filed on Jun. 29, 2015.

BACKGROUND OF THE INVENTION

The disclosure relates generally to power generation systems, and more particularly, to systems and methods for cooling the exhaust gas of power generation systems.

Utility power producers use combined cycle (CC) power generation systems because of their inherent high efficiencies and installed cost advantage. CC power generation systems typically include a gas turbine, a heat recovery steam generator (HRSG), and a steam turbine. The heat recovery steam generator uses the hot exhaust gas from the gas turbine to create steam, which drives the steam turbine. The combination of a gas turbine and a steam turbine achieves greater efficiency than would be possible independently.

Operational flexibility to meet varying power grid demands at different times of the day is an important consideration in CC power generation systems. The issue becomes more important as intermittent energy sources such as solar and wind are integrated into the power grid. To this extent, CC power generation systems powered by fossil fuels must be capable of increasing/decreasing power output as required to accommodate such intermittent energy sources.

Non-steady state emissions from a CC power generation system (e.g., during start-up) are generally closely scrutinized by regulatory authorities. During start-up, emission control devices employing selective catalytic reduction (SCR) and carbon monoxide (CO) catalysts are not active. To avoid thermal stresses in the steam turbine, the gas turbine has to be held at a lower load to control the HRSG inlet temperature to around 700° F. Since emissions are higher at lower gas turbine loads and the emission control devices are not yet active, emissions during start-up can be an order of magnitude higher than those at steady state operation. Further, operating gas turbines at lower loads for a considerable amount of time reduces the power provided to the power grid during the crucial start-up period.

Large increases in the electrical power demand placed upon an electrical power distribution grid will tend to reduce the electrical operational frequency of the grid, causing an “under-frequency” grid event. For example, a heavy or sudden electrical demand may cause a particular power distribution grid having a nominal operational frequency of 50 Hz to momentarily operate at 49 Hz. In conventional electrical power generation systems that utilize one or more heavy-duty industrial gas turbines for supplying electrical power to the grid, the physical speed of each gas turbine supplying power to the grid is synchronized to the electrical frequency of the grid. To this extent, during an under-frequency grid event in which the frequency of the grid decreases, the physical speed of the gas turbines will also decrease. Unfortunately, as the physical speed of a gas turbine decreases with other factors being equal, its power output correspondingly decreases. Consequently, during an under-frequency grid event, a gas turbine will tend to output a lower power. In the past, a common practice in response to a power grid under-frequency grid event involved increasing the firing temperature of the gas turbine to produce more power in an effort to maintain a predetermined level of output power. Unfortunately, such over-firing of the gas turbine may reduce the operational life expectancy of various hot gas path components within the gas turbine.

BRIEF DESCRIPTION OF THE INVENTION

A first aspect of the disclosure provides an airflow control system for a combined cycle turbomachine system, including: an airflow generation system for attachment to a rotatable shaft of a gas turbine system, the airflow generation system drawing in an excess flow of air through an air intake section; a mixing area for receiving an exhaust gas stream produced by the gas turbine system; an air extraction system for extracting a first portion of the excess flow of air to provide bypass air, and for diverting the bypass air into the mixing area to reduce a temperature of the exhaust gas stream; and an airflow regulation system for diverting a second portion of the excess flow of air into the compressor component and, in response to an under-frequency grid event, for increasing the second portion of the excess flow of air diverted into the compressor component.

A second aspect of the disclosure provides a turbomachine system, including: a gas turbine system including a compressor component, a combustor component, a turbine component, and a shaft driven by the turbine component; a fan coupled to the shaft upstream of the gas turbine system, the fan drawing in an excess flow of air through an air intake section; a mixing area for receiving an exhaust gas stream produced by the gas turbine system; an air extraction system for extracting a first portion of the excess flow of air to provide bypass air, and for diverting the bypass air into the mixing area to reduce a temperature of the exhaust gas stream; an airflow regulation system for diverting a second portion of the excess flow of air into the compressor component and, in response to an under-frequency grid event, for increasing the second portion of the excess flow of air diverted into the compressor component; a heat recovery steam generator for receiving the reduced temperature exhaust gas stream and for generating steam; and

a steam turbine system for receiving the steam generated by the heat recovery steam generator.

A third aspect of the disclosure provides a combined cycle power generation system, including: a gas turbine system including a compressor component, a combustor component, a turbine component, and a shaft driven by the turbine component; an electrical generator coupled to the shaft for generating electricity; a fan coupled to the shaft upstream of the gas turbine system, the fan drawing in an excess flow of air through an air intake section; a mixing area for receiving an exhaust gas stream produced by the gas turbine system; an air extraction system for extracting a first portion of the excess flow of air to provide bypass air, and for diverting the bypass air into the mixing area to reduce a temperature of the exhaust gas stream; an airflow regulation system for diverting a second portion of the excess flow of air into the compressor component and, in response to an under-frequency grid event, for increasing the second portion of the excess flow of air diverted into the compressor component; a heat recovery steam generator for receiving the reduced temperature exhaust gas stream and for generating steam; and a steam turbine system for receiving the steam generated by the heat recovery steam generator.

The illustrative aspects of the present disclosure are designed to solve the problems herein described and/or other problems not discussed.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features of this disclosure will be more readily understood from the following detailed description of the various aspects of the disclosure taken in conjunction with the accompanying drawing that depicts various embodiments of the disclosure.

FIG. 1 shows a schematic diagram of a combined cycle (CC) power generation system according to embodiments.

FIG. 2 depicts an enlarged view of a portion of the CC power generation system of FIG. 1 according to embodiments.

FIG. 3 shows a schematic diagram of a CC power generation system according to embodiments.

FIG. 4 depicts an enlarged view of a portion of the CC power generation system of FIG. 3 according to embodiments.

FIG. 5 is an illustrative cross-sectional view of the bypass enclosure and the compressor component of the CC power generation system taken along line A-A of FIG. 3.

FIG. 6 is an illustrative cross-sectional view of the bypass enclosure and the compressor component of the CC power generation system taken along line B-B of FIG. 4.

FIG. 7 depicts a schematic diagram of a CC power generation system according to embodiments.

FIG. 8 is an illustrative chart depicting various operating conditions during a typical start-up process according to embodiments.

It is noted that the drawing of the disclosure is not to scale. The drawing is intended to depict only typical aspects of the disclosure, and therefore should not be considered as limiting the scope of the disclosure. In the drawing, like numbering represents like elements between the drawings.

DETAILED DESCRIPTION OF THE INVENTION

As indicated above, the disclosure relates generally to power generation systems, and more particularly, to systems and methods for cooling the exhaust gas of power generation systems.

FIGS. 1 and 3 depict block diagrams of turbomachine systems (e.g., combined cycle (CC) power generation systems 10). According to embodiments, the CC power generation systems 10 each include a gas turbine system 12 and a heat recovery steam generator (HRSG system 14). The gas turbine system 12 may combust liquid or gas fuel, such as natural gas and/or a hydrogen-rich synthetic gas, to generate hot combustion gases to drive the gas turbine system 12.

The gas turbine system 12 includes an air intake section 16, a compressor component 18, a combustor component 20, and a turbine component 22. The turbine component 22 is drivingly coupled to the compressor component 18 via a shaft 24. In operation, air (e.g., ambient air) enters the gas turbine system 12 through the air intake section 16 (indicated by arrow 26) and is pressurized in the compressor component 18. The compressor component 18 includes at least one stage including a plurality of compressor blades coupled to the shaft 24. Rotation of the shaft 24 causes a corresponding rotation of the compressor blades, thereby drawing air into the compressor component 18 via the air intake section 16 and compressing the air prior to entry into the combustor component 20.

The combustor component 20 may include one or more combustors. In embodiments, a plurality of combustors are disposed in the combustor component 20 at multiple circumferential positions in a generally circular or annular configuration about the shaft 24. As compressed air exits the compressor component 18 and enters the combustor component 20, the compressed air is mixed with fuel for combustion within the combustor(s). For example, the combustor(s) may include one or more fuel nozzles that are configured to inject a fuel-air mixture into the combustor(s) in a suitable ratio for combustion, emissions control, fuel consumption, power output, and so forth. Combustion of the fuel-air mixture generates hot pressurized exhaust gases, which may then be utilized to drive one or more turbine stages (each having a plurality of turbine blades) within the turbine component 22.

In operation, the combustion gases flowing into and through the turbine component 22 flow against and between the turbine blades, thereby driving the turbine blades and, thus, the shaft 24 into rotation. In the turbine component 22, the energy of the combustion gases is converted into work, some of which is used to drive the compressor component 18 through the rotating shaft 24, with the remainder available for useful work to drive a load such as, but not limited to, an electrical generator 28 for producing electricity, and/or another turbine(s).

The combustion gases that flow through the turbine component 22 exit the downstream end 30 of the turbine component 22 as a stream of exhaust gas 32. The exhaust gas stream 32 flows in a downstream direction 34 into a mixing area 36 and toward/into the HRSG system 14.

The HRSG system 14 generally comprises a heat exchanger 40 that recovers heat from the exhaust gas stream 32 of the gas turbine system 12 to produce steam 42. The steam 42 may be used to drive one or more steam turbine systems 44. Each steam turbine system 44 may be coupled via a shaft 142 to one or more electrical generators 144 for producing electricity. The combination of the gas turbine system 12 and the steam turbine system 44 generally produces electricity more efficiently than either the gas turbine system 12 or steam turbine system 44 alone. The steam 42 generated by the HRSG system 14 may also be used in other processes, such as district heating or other process heating. In embodiments, the HRSG system 14 may further include a duct burner system 46 that is configured to burn fuel 48 (e.g., natural gas) in a combustion chamber 50 in order to increase the quantity and/or temperature of the steam 42 generated in the HRSG system 14.

As depicted in FIG. 1, an air generation system comprising, for example, a fan 60, may be coupled to the shaft 24 of the gas turbine system 12 upstream of the gas turbine system 12. The fan 60 may be used to draw in a supply of cooling air (e.g., ambient air) through the air intake section 16. In embodiments, at least a portion of the air drawn in by the fan 60 may be used to lower the temperature of the exhaust gas stream 32 and/or increase the flow of air into the compressor component 18.

The fan 60 may be fixedly mounted (e.g. bolted, welded, etc.) to the shaft 24 of the gas turbine system 12. To this extent, the fan 60 is configured to rotate at the same rotational speed as the shaft 24.

The compressor component 18 has a flow rate capacity and is configured to draw in a flow of air (e.g., ambient air) via the air intake section 16 based on its flow rate capacity. In operation, the fan 60 is designed to draw in an additional flow of air through the air intake section 16 that is about 10% to about 40% of the flow rate capacity of the compressor component 18. In general, the percentage increase in the flow of air may be varied and selectively controlled based on several factors including the load on the gas turbine system 12, the temperature of the air being drawn into the gas turbine system 12, the temperature of the exhaust gas stream 32 at the HRSG system 14, etc.

As depicted in FIG. 2, an inlet guide vane assembly 62 including a plurality of inlet guide vanes 64 may be used to control the amount of air available to the fan 60 and the compressor component 18. Each inlet guide vane 64 may be selectively controlled (e.g., rotated) by an independent actuator 66. Actuators 66 according to various embodiments are shown schematically in FIG. 2, but any known actuator may be utilized. For example, the actuators 66 may comprise an electro-mechanical motor, or any other type of suitable actuator.

The actuators 66 may be independently and/or collectively controlled in response to commands from an airflow controller 100 to selectively vary the positioning of the inlet guide vanes 64. That is, the inlet guide vanes 64 may be selectively rotated about a pivot axis by the actuators 66. In embodiments, each inlet guide vane 64 may be individually pivoted independently of any other inlet guide vane 64. In other embodiments, groups of inlet guide vanes 64 may be pivoted independently of other groups of inlet guide vanes 64 (i.e., pivoted in groups of two or more such that every inlet guide vane 64 in a group rotates together the same amount). Position information (e.g., as sensed by electro-mechanical sensors or the like) for each of the inlet guide vanes 64 may be provided to the airflow controller 100.

The increased flow of air provided by the fan 60 may increase the air pressure at the compressor component 18. For example, in the case where the flow of air is increased by the fan 60 from about 10% to about 40% of the flow rate capacity of the compressor component 18, a corresponding pressure increase of about 5 to about 15 inches of water may be achieved. This pressure increase may be used to overcome pressure drop and facilitate proper mixing (described below) of cooler air with the exhaust gas stream 32 in the mixing area 36. The pressure increase may also be used to supercharge the gas turbine system 12.

Referring to FIGS. 1 and 2, an airflow regulation system 70 may be employed to extract at least some of the additional flow of air provided by the fan 60. A flow of air 72 may be extracted using, for example, one or more extraction ducts 74 (FIG. 2). The extracted air, or “bypass air” (BA) does not enter the gas turbine system 12, but is instead directed to the mixing area 36 through bypass ducts 76 as indicated by arrows BA, where the bypass air may be used to cool the exhaust gas stream 32. The remaining air (i.e., any portion of the additional flow of air generated by the fan 60 not extracted via the extraction ducts 74) enters the compressor component 18 of the gas turbine system 12 and flows through the gas turbine system 12 in a normal fashion. If the flow of remaining air is greater than the flow rate capacity of the compressor component 18 of the gas turbine system 12, a supercharging of the gas turbine system 12 may occur, increasing the efficiency and power output of the gas turbine system 12.

The bypass air may be routed toward the mixing area 36 downstream of the turbine component 22 through one or more bypass ducts 76. The bypass air exits the bypass ducts 76 and enters the mixing area 36 through a bypass air injection grid 110 (FIG. 1), where the bypass air (e.g., ambient air) mixes with and cools the exhaust gas stream 32. In embodiments, the temperature of the exhaust gas stream 32 generated by the gas turbine system 12 is cooled by the bypass air from about 1100° F. to about 600° F.-1000° F. in the mixing area 36. The bypass air injection grid 110 may comprise, for example, a plurality of nozzles 112 or the like for directing (e.g., injecting) the bypass air into the mixing area 36. The nozzles 112 of the bypass air injection grid 110 may be distributed about the mixing area 36 in such a way as to maximize mixing of the bypass air and the exhaust gas stream 32 in the mixing area 36. The nozzles 112 of the bypass air injection grid 110 may be fixed in position and/or may be movable to selectively adjust the injection direction of bypass air into the mixing area 36.

A supplemental mixing system 38 (FIG. 1) may be positioned within the mixing area 36 to enhance the mixing process. The supplemental mixing system 38 may comprise, for example, a static mixer, baffles, and/or the like.

As depicted in FIG. 2, the air flow 72 flowing into each extraction duct 74 (and thus the air flow 172 entering the compressor component 18 of the gas turbine system 12) may be selectively controlled using a flow restriction system 80 comprising, for example, a damper 82, guide vane, or other device capable of selectively restricting airflow. Each damper 82 may be selectively controlled (e.g., rotated) by an independent actuator 84. The actuators 84 may comprise electro-mechanical motors, or any other type of suitable actuator. The dampers 82 may be independently and/or collectively controlled in response to commands from the airflow controller 100 to selectively vary the positioning of the dampers 82 such that a desired amount of bypass air is directed into the mixing area 36 via the bypass ducts 76 and a desired amount of air flow 172 is directed into the compressor component 18 of the gas turbine system 12. Position information (e.g., as sensed by electro-mechanical sensors or the like) for each of the dampers 82 may be provided to the airflow controller 100.

Bypass air may be selectively released from one or more of the bypass ducts 76 using an air release system 86 comprising, for example, one or more dampers 88 (or other devices capable of selectively restricting airflow, e.g. guide vanes) located in one or more air outlets 90. The position of a damper 88 within an air outlet 90 may be selectively controlled (e.g., rotated) by an independent actuator 92. The actuator 92 may comprise an electro-mechanical motor, or any other type of suitable actuator. Each damper 88 may be controlled in response to commands from the airflow controller 100 to selectively vary the positioning of the damper 88 such that a desired amount of bypass air may be released from a bypass duct 76. Position information (e.g., as sensed by electro-mechanical sensors or the like) for each damper 88 may be provided to the airflow controller 100. Further airflow control may be provided by releasing bypass air from one or more of the bypass ducts 76 through one or more metering valves 94 controlled via commands from the airflow controller 100.

The airflow controller 100 may be used to regulate the amount of air generated by the fan 60 that is diverted as bypass air through the bypass ducts 76 and into the mixing area 36 relative to the amount of air that enters the gas turbine system 12 (and exits as the exhaust gas stream 32). Air may be regulated, for example, to control the temperature of the exhaust gas stream 32 at the HRSG system 14. That is, the amount of bypass air flowing through the bypass ducts 76 into the mixing area 36 may be varied (e.g., under control of the airflow controller 100) as the temperature of the exhaust gas stream 32 changes, in order to regulate the temperature at the HRSG system 14.

Further, the air flow 172 entering the compressor component 18 of the gas turbine system 12 may be regulated by the airflow controller 100 in response to an under-frequency grid event. The airflow controller 100 may be configured to monitor the frequency of the electrical grid or may be provided with data regarding the frequency of the electrical grid.

In response to an under-frequency grid event, the air flow 172 entering the compressor component 18 may be increased by rotating the dampers 82 of the flow restriction system 80 towards a more closed position in response to commands from the airflow controller 100. This restricts and reduces the air flow 72 passing through the extraction ducts 74 into the bypass ducts 76 and increases the air flow 172 entering the compressor component 18 of the gas turbine 12. By increasing the air flow 172 entering the compressor component 18 in response to an under-frequency grid event, the power generated by the gas turbine system 12 increases. This allows quick frequency adjustments to compensate for variable electric grid demands. When the under-frequency grid event is no longer an issue, the dampers 82 of the flow restriction system 80 may be rotated towards a more open position, in response to commands from the airflow controller 100, to increase the air flow 72 passing through the extraction ducts 74 into the bypass ducts 76. This reduces the air flow 172 entering the compressor component 18 of the gas turbine system 12, causing a corresponding decrease in the power generated by the gas turbine system 12.

The airflow controller 100 may receive data 102 associated with the operation of the CC power generation system 10. Such data may include, for example, grid frequency information, the temperature of the exhaust gas stream 32 as it enters the mixing area 36, the temperature of the exhaust gas stream 32 at the HRSG system 14 after mixing/cooling has occurred in the mixing area 36, the temperature of the air drawn into the air intake section 16 by the fan 60, and other temperature data obtained at various locations within the CC power generation system 10. The data 102 may further include airflow and pressure data obtained, for example, within the air intake section 16, at the inlet guide vanes 64, at the fan 60, at the entrance of the compressor component 18, within the extraction ducts 74, at the dampers 82, within the bypass ducts 76, at the downstream end 30 of the turbine component 22, and at various other locations within the CC power generation system 10. Load data, fuel consumption data, and other information associated with the operation of the gas turbine system 12 may also be provided to the airflow controller 100. The airflow controller 100 may further receive positional information associated with the inlet guide vanes 64, dampers 82, 88, valve 94, etc. It should be readily apparent to those skilled in the art how such data may be obtained (e.g., using appropriate sensors, feedback data, etc.), and further details regarding the obtaining of such data will not be provided herein.

Based on the received data 102, the airflow controller 100 is configured to vary as needed: the amount of bypass air flowing through the bypass ducts 76 into the mixing area 36 to maintain the temperature at the HRSG system 14 at a suitable level; and the air flow 172 entering the compressor component 18 (e.g., in response to an under-frequency grid event). These actions may be achieved, for example, by varying at least one of: the flow of air drawn into the air intake section 16 by the fan 60 (this flow may be controlled, for example, by adjusting the position of one or more of the inlet guide vanes 64 and/or by increasing the rotational speed of the shaft 24); the flow of air 72 passing into the extraction ducts 74 (this flow may be controlled, for example, by adjusting the position of one or more of the dampers 82); the air flow 172 entering the compressor component 18 (this flow may be controlled, for example, by adjusting the position of one or more of the dampers 82); and the flow of bypass air passing from the extraction ducts 74, through the bypass ducts 76, into the mixing area 36 (this flow may be controlled, for example, by adjusting the position of one or more of the dampers 82, 88 and/or the operational status of the metering valves 94).

The airflow controller 100 may include a computer system having at least one processor that executes program code configured to control the amount of bypass air flowing through the bypass ducts 76 into the mixing area 36 and the air flow 172 entering the compressor component 18 of the gas turbine system 12 using, for example, data 102 and/or instructions from human operators. The commands generated by the airflow controller 100 may be used to control the operation of various components (e.g., such as actuators 66, 84, 92, valve 94, and/or the like) in the CC power generation system 10. For example, the commands generated by the airflow controller 100 may be used to control the operation of the actuators 66, 84, and 92 to control the rotational position of the inlet guide vanes 64, dampers 82, and dampers 88, respectively. Commands generated by the airflow controller 100 may also be used to activate other control settings in the CC power generation system 10.

As depicted in FIGS. 3 and 4, instead of using external bypass ducts 76, the gas turbine system 12 may be surrounded by a bypass enclosure 111. The bypass enclosure 111 may extend from, and fluidly couple, the air intake section 16 to the mixing area 36. The bypass enclosure 111 may have any suitable configuration. For instance, the bypass enclosure 111 may have an annular configuration as depicted in FIG. 5, which is a cross-section taken along line A-A in FIG. 3. The bypass enclosure 111 forms an air passage 113 around the gas turbine system 12 through which a supply of cooling bypass air (BA) may be provided for cooling the exhaust gas stream 32 of the gas turbine system 12.

An airflow regulation system 114 may be provided to extract at least some of the additional flow of air provided by the fan 60 and to direct the extracted air into the air passage 113 formed between the bypass enclosure 111 and the gas turbine system 12. The airflow regulation system 114 may comprise, for example, dampers, inlet guide vanes, a stator, or any other suitable system for selectively directing a flow of air into the air passage 113. In the following description, the airflow regulation system 114 comprises, but is not limited to, dampers. As shown in FIG. 6, which is a cross-section taken along line B-B in FIG. 4, the airflow regulation system 114 may extend completely around the entrance to the air passage 113 formed between the bypass enclosure 111 and the compressor component 18 of the gas turbine system 12.

As depicted in FIG. 4, the airflow regulation system 114 may include a plurality of dampers 116 for controlling: the amount of bypass air (BA) flowing into the air passage 113 formed between the bypass enclosure 111 and the gas turbine system 12; and the air flow 172 passing into the compressor component 18 of the gas turbine system 12. Each damper 116 may be selectively and independently controlled (e.g., rotated) by an independent actuator 118. The actuators 118 are shown schematically in FIG. 4, but any known actuator may be utilized. For example, the actuators 118 may comprise an electro-mechanical motor, or any other type of suitable actuator.

The actuators 118 of the airflow regulation system 114 may be independently and/or collectively controlled in response to commands from the airflow controller 100 to selectively vary the positioning of the dampers 116. That is, the dampers 116 may be selectively rotated about a pivot axis by the actuators 118. In embodiments, each damper 116 may be individually pivoted independently of any other damper 116. In other embodiments, groups of dampers 116 may be pivoted independently of other groups of dampers 116 (i.e., pivoted in groups of two or more such that every damper 116 in a group rotates together the same amount). Position information (e.g., as sensed by electro-mechanical sensors or the like) for each of the dampers 116 may be provided to the airflow controller 100.

The bypass air does not enter the gas turbine system 12, but is instead directed to the mixing area 36 through the air passage 113 as indicated by arrows BA, where the bypass air may be used to cool the exhaust gas stream 32. The remaining air (i.e., any portion of the additional flow of air generated by the fan 60 not extracted via the airflow regulation system 114 (e.g., air flow 172 in FIG. 4)) enters the compressor component 18 of the gas turbine system 12 and flows through the gas turbine system 12 in a normal fashion. If the flow of remaining air is greater than the flow rate capacity of the compressor component 18 of the gas turbine system 12, a supercharging of the gas turbine system 12 may occur, increasing the efficiency and power output of the gas turbine system 12.

The bypass air flows toward and into the mixing area 36 downstream of the turbine component 22 through the air passage 113. In embodiments, the bypass air exits the air passage 113 and is directed at an angle toward and into the exhaust gas stream 32 in the mixing area 36 to enhance mixing. In the mixing area 36, the bypass air (e.g., ambient air) mixes with and cools the exhaust gas stream 32 to a temperature suitable for use in the HRSG system 14. In embodiments, the temperature of the exhaust gas stream 32 generated by the gas turbine system 12 is cooled by the bypass air from about 1100° F. to about 600° F.-1000° F. in the mixing area 36.

As depicted in FIGS. 3 and 4, the distal end 120 of the bypass enclosure 111 may curve inwardly toward the mixing area 36 to direct the bypass air at an angle toward and into the exhaust gas stream 32 in the mixing area 36. The intersecting flows of the bypass air and the exhaust gas stream 32 may facilitate mixing, thereby enhancing the cooling of the exhaust gas stream 32. A flow directing system 122 may also be provided to direct the bypass air at an angle toward and into the exhaust gas stream 32. Such a flow directing system 122 may include, for example, outlet guide vanes, stators, nozzles, or any other suitable system for selectively directing the flow of bypass air into the mixing area 36.

An illustrative flow directing system 122 is shown in FIG. 4. In this example, the flow directing system 122 includes a plurality of outlet guide vanes 124. Each outlet guide vane 124 may be selectively controlled (e.g., rotated) by an independent actuator 126. The actuators 126 are shown schematically in FIG. 4, but any known actuator may be utilized. For example, the actuators 126 may comprise an electro-mechanical motor, or any other type of suitable actuator. In embodiments, the flow directing system 122 may extend completely around the exit of the air passage 113 formed between the bypass enclosure 111 and the turbine component 22 of the gas turbine system 12.

A supplemental mixing system 38 (FIG. 3) may be positioned within the mixing area 36 to enhance the mixing process. The supplemental mixing system 38 may comprise, for example, a static mixer, baffles, and/or the like.

As shown in FIG. 4, bypass air may be selectively released from the bypass enclosure 111 using an air release system 130 comprising, for example, one or more dampers 132 (or other devices capable of selectively restricting airflow, e.g. guide vanes) located in one or more air outlets 134. The position of a damper 132 within an air outlet 134 may be selectively controlled (e.g., rotated) by an independent actuator 136. The actuator 136 may comprise an electro-mechanical motor, or any other type of suitable actuator. Each damper 132 may be controlled in response to commands from the airflow controller 100 to selectively vary the positioning of the damper 132 such that a desired amount of bypass air may be released from the bypass enclosure 111. Position information (e.g., as sensed by electro-mechanical sensors or the like) for each damper 132 may be provided to the airflow controller 100. Further airflow control may be provided by releasing bypass air from the bypass enclosure 111 through one or more metering valves 140 (FIG. 4) controlled via commands from the airflow controller 100.

The airflow controller 100 may be used to regulate the amount of air generated by the fan 60 that is diverted as bypass air into the mixing area 36 through the air passage 113 relative to the amount of air that enters the gas turbine system 12 (and exits as the exhaust gas stream 32) in order to control the temperature at the HRSG system 14 under varying operating conditions. The amount of bypass air flowing through the air passage 113 into the mixing area 36 may be varied (e.g., under control of the airflow controller 100) as the temperature of the exhaust gas stream 32 changes, in order to regulate the temperature at the HRSG system 14.

According to embodiments, the air flow 172 entering the compressor component 18 of the gas turbine system 12 may be regulated by the airflow controller 100 in response to an under-frequency grid event. The airflow controller 100 may be configured to monitor the frequency of the electrical grid or may be provided with data regarding the frequency of the electrical grid.

In response to an under-frequency grid event, the air flow 172 passing into the compressor component 18 may be increased by rotating the dampers 116 of the airflow regulation system 114 towards a more closed position in response to commands from the airflow controller 100. This restricts and reduces the flow of bypass air flowing into the air passage 113 and increases the air flow 172 entering the compressor component 18 of the gas turbine system 12. By increasing the air flow 172 passing into the compressor component 18 in response to an under-frequency grid event, the power generated by the gas turbine system 12 increases. This allows quick frequency adjustments to compensate for variable electric grid demands. When the under-frequency grid event is no longer an issue, the dampers 116 of the airflow regulation system 114 may be rotated towards a more open position, in response to commands from the airflow controller 100, to increase the flow of bypass air passing into and through the air passage 113. This reduces the airflow 172 passing into the compressor component 18 of the gas turbine system 12, causing a corresponding decrease in the power generated by the gas turbine system 12.

As shown schematically in FIG. 4, the bypass enclosure 111 may be provided with one or more access doors 150. The access doors 150 provide access through the bypass enclosure 111 to the various components of the gas turbine system 12 (e.g., for servicing, repair, etc.).

In other embodiments, as depicted in FIG. 7, the gas turbine casing 160 itself can be used in lieu of the enclosure 111. This configuration operates similarly to the system depicted in FIGS. 3 and 4, except that the airflow regulation system 114 and flow directing system 122 are disposed within the gas turbine casing 160. The fuel/combustor inlets 162 of the combustor component 20 of the gas turbine system 12 may extend through the gas turbine casing 160 (e.g., for easier access). In this configuration, bypass air (BA) passes between the gas turbine casing 160 and the exterior of the compressor component 18, combustor component 20, and turbine component 22. Other components depicted in FIGS. 3 and 4, such as the air intake section, HRSG system, airflow controller, etc. are not shown, for sake of clarity in FIG. 7.

In operation, a portion of the air drawn in by an air generation system (e.g., the fan 60) is directed by the airflow regulation system 114 as bypass air into an air passage 164 formed between the gas turbine casing 160 and the exterior of the compressor component 18, combustor component 20, and turbine component 22. The bypass air exits the air passage 164 and is directed at an angle by the flow directing system 122 toward and into the exhaust gas stream 32 in the mixing area 36. In the mixing area 36, the bypass air (e.g., ambient air) mixes with and cools the exhaust gas stream 32. The temperature of the exhaust gas stream 32 generated by the gas turbine system 12 may be cooled by the bypass air from about 1100° F. to about 600° F.-1000° F. in the mixing area 36. If necessary, in response to an under-frequency grid event, the air flow 172 into the compressor component 18 may be increased by rotating the dampers of the airflow regulation system 114 towards a more closed position to restrict and reduce the flow of bypass air into the air passage 112. By increasing the air flow 172 passing into the compressor component 18 in response to an under-frequency grid event, the frequency of the gas turbine system 12, as well as the power generated by the gas turbine system 12, increases.

As detailed above, the airflow controller 100 may receive a wide variety of data 102 associated with the operation of the CC power generation system 10 and the components thereof. Based on the received data 102, the airflow controller 100 is configured to vary as needed: the amount of bypass air flowing through the air passage 113, 164 into the mixing area 36 to regulate the temperature at the HRSG system 14; and the air flow 172 entering the compressor component 18 of the gas turbine system 12 (e.g., in response to an under-frequency grid event). These actions may be achieved, for example, by varying at least one of: the flow of air drawn into the air intake section 16 by the fan 60 and compressor component 18 of the gas turbine system 12; the flow of air directed into the air passage 113, 164 via the airflow regulation system 114 (this flow may be controlled, for example, by adjusting the position of one or more of the dampers 116); the air flow 172 passing into the compressor component 18 (this flow may be controlled, for example, by adjusting the position of one or more of the dampers 116); and the flow of bypass air through the air passage 113, 164 into the mixing area 36 (this flow may be controlled, for example, by adjusting the position of one or more of the dampers 116, 132 and/or the operational status of the metering valves 140).

Examples of the start-up operation and the normal steady state operation of the CC power generation system 10 will now be provided with reference to FIGS. 1, 3, and 8.

Start-Up Operation

During a start-up process in a conventional CC power generation system, the gas turbine needs to be parked at a lower load (e.g., compared to the minimum emissions compliance load (MECL)), which results in higher NO_(x) and CO emissions. This is done, for example, to maintain the temperature of the steam entering the steam turbine to around 700° F. to avoid thermal stresses in the steam turbine. This lower load is indicated by point “A” in FIG. 8.

In contrast, according to embodiments, in a CC power generation system 10 including a fan 60 for generating bypass air for cooling an exhaust gas stream 32 of a gas turbine system 12, the gas turbine system 12 can be parked at a higher load (as indicated by point “B” in FIG. 8) with a higher exhaust temperature. At the higher exhaust temperature, the NO_(x) and CO emissions in the exhaust gas stream 32 are lower. The temperature of the exhaust gas stream 32 of the gas turbine system 12 can be controlled using the bypass air (BA) to provide an inlet temperature of about 700° F. at the HRSG system 14. This results in lower start-up NO_(x) and CO emissions and also helps to increase the power output of the gas turbine system 12 during start-up. Comparing point A and point B in FIG. 8, for example, it can easily be seen that the gas turbine system 12 can be operated (point B) at a higher temperature and higher load than a conventional gas turbine system (point A), while still providing an inlet temperature of about 700° F. at the HRSG system 14.

Normal Operation

During normal operation, a portion of the flow of air generated by the fan 60 may be used to supercharge the compressor component 18 of the gas turbine system 12, thereby boosting the power output of the gas turbine system 12. Further, the bypass air mixed back into the exhaust gas stream 32 of the gas turbine system 12 increases the flow into the HRSG system 14 and reduces the temperature of the flow. This allows increased firing in the duct burner system 46 without reaching the tube temperature limit of the HRSG system 14 (e.g., around 1600° F.). This also allows increased power output from the bottoming cycle of the CC power generation system 10. In embodiments, the power output of the CC power generation system 10 can be increased, for example, by 10 to 15% compared to the power output of a conventional CC power generation system (i.e., no fan).

In embodiments, several parameters can be regulated to control the power output of the CC power generation system 10, including:

1) the amount of supercharging of the compressor component 18 of the gas turbine system 12;

2) the amount of bypass flow provided to the mixing area 36 to cool the exhaust gas stream 32;

3) the air flow 172 passing into the compressor component 18 in response to an under-frequency grid event to vary the power generated by the gas turbine system 12;

4) the ratio (i.e., “bypass ratio”) of bypass flow versus flow into the gas turbine system 12 provided by the airflow regulation system 70;

5) the amount of firing of the duct burner system 46 (e.g., to move temperature of the exhaust gas flow to a target level after the bypass air has been injected into the exhaust gas stream 32); and

6) the amount of overfiring or underfiring of the gas turbine system 12 (to provide as much energy as feasible in the topping cycle).

Many advantages may be provided by the disclosed CC power generation system 10. For example, the power output of the gas turbine system 12 may be increased due to the supercharging of the inlet air to the compressor component 18 by the fan 60. Further, high duct burner firing is possible without reaching the HRSG tube temperature limit, resulting in higher bottoming cycle power output. In addition, the gas turbine system 12 may be run during start-up at a higher load point. This results in lower emissions and an exhaust gas stream 32 having a temperature higher than that needed for the steam turbine system 44. Even further, quick frequency adjustments can be made to compensate for variable electric grid demands.

The use of an air generation system (such as fan 60) in lieu of conventional large external blower systems and/or other conventional cooling structures provides many other advantages. For example, the need for redundant external blower systems and associated components (e.g., blowers, motors and associated air intake structures, filters, ducts, etc.) required by conventional exhaust stream cooling systems is eliminated. This reduces manufacturing and operating costs, as well as the overall footprint, of the CC power generation system 10. The footprint is further reduced as the fan 60 draw in air through an existing air intake section 16, rather than through separate, dedicated intake structures often used with external blower systems.

Use of the fan 60 provides a more reliable and efficient CC power generation system 10. For example, since the bypass air used for cooling in the mixing area 36 is driven by the shaft 24 of the gas turbine system 12 itself, large external blower systems are no longer required. Further, at least a portion of the flow of air generated by the fan 60 may be used to supercharge the gas turbine system 12.

Power requirements of the CC power generation system 10 are reduced because the fan 60 is coupled to, and driven by, the shaft 24 of the gas turbine system 12. This configuration eliminates the need for large blower motors commonly used in conventional external blower cooling systems.

In various embodiments, components described as being “coupled” to one another can be joined along one or more interfaces. In some embodiments, these interfaces can include junctions between distinct components, and in other cases, these interfaces can include a solidly and/or integrally formed interconnection. That is, in some cases, components that are “coupled” to one another can be simultaneously formed to define a single continuous member. However, in other embodiments, these coupled components can be formed as separate members and be subsequently joined through known processes (e.g., fastening, ultrasonic welding, bonding).

When an element or layer is referred to as being “on”, “engaged to”, “connected to” or “coupled to” another element, it may be directly on, engaged, connected or coupled to the other element, or intervening elements may be present. In contrast, when an element is referred to as being “directly on,” “directly engaged to”, “directly connected to” or “directly coupled to” another element, there may be no intervening elements or layers present. Other words used to describe the relationship between elements should be interpreted in a like fashion (e.g., “between” versus “directly between,” “adjacent” versus “directly adjacent,” etc.). As used herein, the term “and/or” includes any and all combinations of one or more of the associated listed items.

The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the disclosure. As used herein, the singular forms “a”, “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms “comprises” and/or “comprising,” when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.

This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims. 

What is claimed is:
 1. An airflow control system for a combined cycle turbomachine system, comprising: an airflow generation system for attachment to a rotatable shaft of a gas turbine system, the gas turbine system including a compressor component, a combustor component, and a turbine component, the airflow generation system drawing in an excess flow of air through an air intake section; a mixing area for receiving an exhaust gas stream produced by the gas turbine system; an air extraction system for: extracting a first portion of the excess flow of air to provide bypass air, and for diverting the bypass air through a bypass duct completely around the compressor component, combustor component, and turbine component of the gas turbine system into the mixing area to reduce a temperature of the exhaust gas stream; and diverting a second portion of the excess flow of air, providing the second portion of the excess flow of air into the compressor component and, in response to an under-frequency grid event detected by an airflow controller, increasing the second portion of the excess flow of air diverted into the compressor component; wherein the air extraction system includes: a flow control system for controlling the bypass air passing through the bypass duct, the flow control system including a damper assembly actively controlled by the airflow controller for regulating the bypass air passing through the bypass duct; and an actively controlled air release system upstream from the mixing area and actively controlled by the airflow controller for selectively releasing a portion of the bypass air from the bypass duct to an exterior of the gas turbine system to control the temperature of the exhaust.
 2. The airflow control system of claim 1, wherein the air extraction system is further configured to decrease the bypass air diverted into the mixing area in response to the under-frequency grid event detected by the airflow controller.
 3. The airflow control system of claim 1, wherein the excess flow of air drawn in by the airflow generation system comprises about 10 percent to about 40 percent of a flow of air drawn in by the compressor component of the gas turbine system.
 4. The airflow control system of claim 1, wherein the airflow generation system comprises a fan.
 5. The airflow control system of claim 1, further comprising a duct burner system for heating the reduced temperature exhaust gas stream.
 6. The airflow control system of claim 1, further comprising a heat recovery steam generator for receiving the reduced temperature exhaust gas stream and for generating steam, wherein the airflow controller controls the damper assembly and the air release system of the flow control system to control the temperature of the exhaust gas entering the heat recovery steam generator.
 7. A turbomachine system, comprising: a gas turbine system including a compressor component, a combustor component, a turbine component, and a shaft driven by the turbine component; a fan coupled to the shaft upstream of the gas turbine system, the fan drawing in an excess flow of air through an air intake section; a mixing area for receiving an exhaust gas stream produced by the gas turbine system; an air extraction system for: extracting a first portion of the excess flow of air to provide bypass air, and for diverting the bypass air through a bypass duct completely around the compressor component, combustor component, and turbine component of the gas turbine system into the mixing area to reduce a temperature of the exhaust gas stream; diverting a second portion of the excess flow of air, providing the second portion of the excess flow of air into the compressor component and, in response to an under-frequency grid event detected by an airflow controller, increasing the second portion of the excess flow of air diverted into the compressor component; wherein the air extraction system includes: a flow control system for controlling the bypass air passing through the bypass duct, the flow control system including a damper assembly actively controlled by the airflow controller for regulating the bypass air passing through the bypass duct; and an actively controlled air release system upstream from the mixing area and actively controlled by the airflow controller for selectively releasing a portion of the bypass air from the bypass duct to an exterior of the gas turbine system to control the temperature of the exhaust; a heat recovery steam generator for receiving the reduced temperature exhaust gas stream and for generating steam; and a steam turbine system for receiving the steam generated by the heat recovery steam generator, wherein the airflow controller controls the damper assembly and the air release system of the flow control system to control the temperature of the exhaust gas entering the heat recovery steam generator.
 8. The turbomachine system of claim 7, wherein the air extraction system is further configured to decrease the bypass air diverted into the mixing area in response to the under-frequency grid event detected by the airflow controller.
 9. The turbomachine system of claim 7, wherein the excess flow of air drawn in by the airflow generation system comprises about 10 percent to about 40 percent of a flow of air drawn in by the compressor component of the gas turbine system.
 10. The turbomachine system of claim 7, further comprising a duct burner system upstream of the heat recovery steam generator for heating the reduced temperature exhaust gas stream.
 11. A combined cycle power generation system, comprising: a gas turbine system including a compressor component, a combustor component, a turbine component, and a shaft driven by the turbine component; an electrical generator coupled to the shaft for generating electricity; a fan coupled to the shaft upstream of the gas turbine system, the fan drawing in an excess flow of air through an air intake section; a mixing area for receiving an exhaust gas stream produced by the gas turbine system; an air extraction system for: extracting a first portion of the excess flow of air to provide bypass air, and for diverting the bypass air through a bypass duct completely around the compressor component, combustor component, and turbine component of the gas turbine system into the mixing area to reduce a temperature of the exhaust gas stream; for diverting a second portion of the excess flow of air, providing the second portion of the excess flow of air into the compressor component and, in response to an under-frequency grid event detected by an airflow controller, increasing the second portion of the excess flow of air diverted into the compressor component; wherein the air extraction system includes: a flow control system for controlling the bypass air passing through the bypass duct, the flow control system including a damper assembly actively controlled by the airflow controller for regulating the bypass air passing through the bypass duct; and an actively controlled air release system upstream from the mixing area and actively controlled by the airflow controller for selectively releasing a portion of the bypass air from the bypass duct to an exterior of the gas turbine system to control the temperature of the exhaust; a heat recovery steam generator for receiving the reduced temperature exhaust gas stream and for generating steam; and a steam turbine system for receiving the steam generated by the heat recovery steam generator, wherein the airflow controller controls the damper assembly and the air release system of the flow control system to control the temperature of the exhaust gas entering the heat recovery steam generator.
 12. The combined cycle power generation system of claim 11, wherein the excess flow of air drawn in by the airflow generation system comprises about 10 percent to about 40 percent of a flow of air drawn in by the compressor component of the gas turbine system. 